1. Field of the Invention
The invention relates generally to tools for well logging. More particularly, the invention relates to devices and methods for reducing stand-off effects in downhole tools.
2. Background Art
Oil and gas industry uses various tools to probe the formation to locate hydrocarbon reservoirs and to determine the types and quantities of hydrocarbons. A typical logging tool transmits energy (a signal) from a source (e.g., a transmitter of a propagation tool or a gamma-ray source of a density logging tool) into the borehole and the formation. The transmitted signal interacts with matters in the formation when it traverses the formation. As a result of these interactions, the properties of the transmitted signal is altered, and some of the altered signals may return to the borehole and the tool. One or more sensors (e.g., receivers) may be disposed on the tool to detect the returned signals. The detected signals can then be analyzed to provide insights into the formation properties.
Ideally, the receivers detect only the signals returned from the formation. However, if the transmitters and the receivers do not directly contact the formation (i.e., tool stand-off), the borehole and the borehole fluid often provide an alternate transmission pathway for the signals to travel from the transmitters to the receivers. Signal transmitted in the borehole may be generally referred to as “trapped signals,” which complicate the measurements and may render the analysis of the desired signals difficult or impossible.
Various approaches are known in the art for reducing or eliminating tool stand-off effects (or borehole effects). The following description uses electromagnetic propagation tools as examples to illustrate the problems associated with tool stand-off effects and to illustrate methods for overcoming these effects. One of ordinary skill in the art would appreciate that embodiments of the invention may be used with various tools and are not limited to these specific examples.
Electromagnetic (EM) propagation tools are commonly used to measure the subsurface properties of resistivity and/or dielectric constant. For discussion of EM propagation measurements see: “Theory of Microwave Dielectric Logging Using the Electromagnetic Wave Propagation Method,” Freeman et al., Geophysics, 1979; U.S. Pat. Nos. 4,689,572 and 4,704,581 issued to Clark. EM propagation can also be used to provide borehole imaging while drilling. The boreholes may be drilled with an oil-based mud (OBM) or an water-based mud (WBM). In a typical EM propagation tool, the antennas are mounted on one or more articulated pads. FIGS. 1A-1C show a schematic of a typical EM tool having antennas or magnetic dipole arrays mounted on a pad. FIG. 1A shows a top view of the pad, which typically has dimensions of 20 cm by 8 cm and a thickness of 3 cm. As shown in FIG. 1A, two transmitters T1 and T2 are each disposed on one side of the two receivers R1 and R2 at equal spacings. The two transmitters T1 and T2 can be sequentially fired to provide compensated measurements, as disclosed in U.S. Pat. No. 3,849,721 issued to Calvert. FIG. 1B shows a side view of the pad, while FIG. 1C shows a cross sectional view of the pad, illustrating the curved pad face that is designed to fit the borehole wall. The curvatures of the pads may be designed to fit a particular borehole diameter (e.g., 6, 8½, or 12½ inches). FIG. 1C also shows that the pad face may be coated with a hardfacing material to make the pad more wear resistant.
The antennas (as shown in FIG. 1A) may be endfire and/or broadside magnetic dipole arrays, which may be operated at a proper frequency (e.g., approximately 1 GHZ for propagation measurements). Other electromagnetic sensors have been proposed for high frequency measurements, for example, using button electrodes that function as normal electric dipoles (being normal to the pad face), crossed magnetic dipoles, and normal magnetic dipoles.
Because stand-off between the sensors and the formation can lead to erroneous measurements, especially in oil based mud, the pads that house the sensors should be articulated to maintain contact with the formation at all times. Ideally, the distance between the pad face and the borehole wall should be 0.1 inches or less.
With the antennas mounted in the articulated pad, cables would need to be routed to the pad (see FIG. 1C). In some tools, it may be necessary to place some front-end electronics in the pad to reduce the number of cables and/or to improve the measurement accuracy. Because the pads are subject to higher shock levels than the drill collars, pad-mounted electronics will have to be designed to survive in harsher environments.
An extremely harsh environment may be encountered by the antennas and electronics mounted in the pad and the cables connecting the pad to the drill collar. For example, if the drill collar is rotating at 120 RPM in an 8.5 inch borehole, then the articulated pad will travel 16,000 ft/hr just from the tool's rotation. In a 100 hour Logging While Drilling (LWD) job, the pad will travel 1,600,000 ft. To put this in perspective, a typical wireline tool travels only a few thousand feet in a logging job. Therefore, the mechanical abuse on an LWD pad in one LWD job is roughly three orders of magnitude greater than on a wireline pad in a wireline job. Hence, abrasion of the antennas could be a significant problem leading to antenna failure and high maintenance and service costs. The minimum reliability for an LWD tool should be 2000 hr, which implies that the pad-mounted antennas need to survive 32,000,000 ft before failures occur.
Mechanical shock for components mounted in an articulated pad is another serious concern. Assuming 120 RPM and one shock per revolution, the pad will experience 7,200 shocks/hr. In a 100 hr job, the pad would experience 720,000 shocks. To achieve an MTBF (Mean Time Between Failure) of 2000 hr, the components would then have to survive 144,000,000 shocks. These numbers arc well above the number of shocks currently experienced by Measurement While Drilling (MWT) or LWD components which are not mounted in an articulated pad. Furthermore, since the is small, lightweight, and articulated, the shock level will be considerably higher in the pad than in die drill collar. Developing antennas and electronics to survive these shock levels is challenging.
Frictional contact between the pad and the formation may also result in the pad being subjected to much higher temperatures than the ambient downhole temperature. Another concern is the repeated stress applied to the cables between the pad and the drill collar. Again assuming 120 RPM, the cables will be twisted 14,400 times per hr (opening and closing the pad every revolution) and 1,440,000 times in a 100 hr LWD job.
The above description shows that while mounting the sensors on articulate pads can overcome most of the adverse effects associated with tool stand-offs, this approach subjects the sensors and the electronics to harsher environments. An alternative is to mount the sensors in non-moving parts of a drill string assembly. For example, U.S. Pat. No. 6,173,793 B1 issued to Thompson et al. discloses tools having sensors mounted in non-rotating pads. While this approach overcomes some problems associated with rotating pads, it is sometimes desirable to have sensors rotate with the drill strings, for example to provide full-bore images. Therefore, there still exists a need for methods that can provide similar benefits of articulating pads without subjecting the sensors to the extremely harsh environment experienced by a typical articulating pad.